Raising full year 2018 production guidance; expect average daily production to increase by 60 – 64% over 2017.

Second quarter production exceeded expectations, increasing 53% year-over-year and 17% sequentially to average 21,046 barrels of oil equivalent (“Boe”) per day.

Exited the second quarter with 16.4 net wells in process after adding 8.1 organic net wells to production.

Announced $500 million in signed acquisitions year-to-date using a combination of cash and equity, which Northern expects to fold into its existing asset base without the addition of new employees.

MANAGEMENT COMMENT

“We are only half way through 2018; however, production has materially exceeded our expectations, cash costs are lower and our success executing on acquisitions has surpassed even our lofty internal goals,” commented Northern’s Chief Executive Officer, Brandon Elliott. “We plan to close our Pivotal Petroleum and W Energy acquisitions at the end of the third quarter, upon which Northern will have reached our goals of substantially growing EBITDA and improving our debt metrics, significantly ahead of plan. We are still not satisfied and continue to aggressively look at all avenues to drive increased growth and returns to our shareholders.”

GUIDANCE

Northern is raising its 2018 production guidance as a result of increased activity as well as the recently announced Pivotal Petroleum and W Energy acquisitions that are expected to close at the end of the third quarter. Northern expects to add approximately 25 – 27 organic net wells to production for the year with a drilling and completion budget of between $200 and $216 million, resulting in a total capital expenditure budget, including acreage, workover and other capitalized costs but excluding announced acquisitions, of between $215 and $230 million. Additional information regarding Northern’s current expectations are included in the tables below.

2018 Production:

Boe Per Day

Year/YearIncrease

1st Quarter – Actual

17,995

35%

2nd Quarter – Actual

21,046

53%

3rd Quarter – Estimate

(Organic + Salt Creek)(1)

23,000 – 24,000

4th Quarter – Estimate

(Organic + Salt Creek + Pivotal + W Energy)(2)

32,500 – 34,000

Annual – Estimate (average Boe per day)(2)

23,670 – 24,300

60% – 64%

__________

(1)

The Salt Creek acquisition closed on June 4, 2018.

(2)

Assumes closing of pending Pivotal Petroleum and W Energy acquisitions at the end of the third quarter of 2018.

Operating Expenses Guidance:

2018

Production Expenses (per Boe)

$7.50 – $8.50

Production Taxes (% of Oil & Gas Sales)

~ 9.2%

General and Administrative Expense (per Boe):

Cash

$1.25 – $1.50

Non-Cash

$0.25 – $0.50

Average Differential to NYMEX WTI

$4.75 – $5.75

SECOND QUARTER 2018 RESULTS

The following tables set forth selected operating and financial data for the periods indicated.

Three Months Ended June 30,

2018

2017

% Change

Net Production:

Oil (Bbl)

1,625,788

1,054,263

54

%

Natural Gas and NGLs (Mcf)

1,736,651

1,206,103

44

%

Total (Boe)

1,915,230

1,255,280

53

%

Average Daily Production:

Oil (Bbl)

17,866

11,585

54

%

Natural Gas and NGLs (Mcf)

19,084

13,254

44

%

Total (Boe)

21,046

13,794

53

%

Three Months Ended

June 30,

2018

2017

Net Sales:

Oil Sales

$

101,036,507

$

43,531,170

Natural Gas and NGL Sales

8,010,371

4,849,836

Gain (Loss) on Settled Derivatives

(12,266,857

)

2,341,030

Total Oil, Natural Gas and NGL Sales Including all Derivative Settlements

96,780,021

50,722,036

Average Sales Prices:

Average NYMEX Price (per Bbl)(1)

$

67.97

$

48.15

Oil Differential (per Bbl)(2)

(5.77

)

(6.86

)

Oil (per Bbl)

62.20

41.29

Effect of Gain (Loss) on Settled Derivatives on Average Price (per Bbl)

(7.55

)

2.22

Oil Net of Settled Derivatives (per Bbl)

54.65

43.51

Natural Gas and NGLs (per Mcf)

4.61

4.02

Realized Price on a Boe Basis Including all Realized Derivative Settlements

50.58

40.41

Operating Expenses:

Production Expenses

$

14,548,922

$

12,137,540

Production Taxes

10,131,843

4,439,774

General and Administrative Expense

3,251,239

4,317,139

Depletion, Depreciation, Amortization and Accretion

22,596,028

13,682,452

Costs and Expenses (per Boe):

Production Expenses

$

7.60

$

9.67

Production Taxes

5.29

3.54

General and Administrative Expense

1.70

3.44

Depletion, Depreciation, Amortization and Accretion

11.80

10.90

Net Income (Loss)

$

(96,546,698

)

$

13,801,859

Net Income (Loss) Per Common Share – Diluted

$

(0.49

)

$

0.22

Adjusted Net Income (Loss)(3)

$

18,041,826

$

(175,490

)

Adjusted Net Income (Loss) Per Common Share – Diluted(3)

$

0.09

$

—

Adjusted EBITDA(3)

$

70,545,647

$

30,746,345

__________

(1)

Based on average NYMEX WTI closing prices.

(2)

Average oil price differential to the NYMEX WTI.

(3)

Please see “Non-GAAP Financial Measures” below for additional information and a reconciliation to the most directly comparable GAAP Measure.

CAPITAL EXPENDITURES & DRILLING ACTIVITY

Three Months Ended

June 30, 2018

Capital Expenditures Incurred:

Drilling and Development Capital Expenditures

$52.3 million

Acquisition of Oil and Natural Gas Properties

$59.8 million

Other

$0.7 million

Net Wells Added to Production (Includes 5.5 Net Salt Creek Additions)

13.6

Net Producing Wells (Period-End)

248.3

Net Wells in Process (Period-End)

16.4

Weighted Average AFE for In-Process Wells (Period-End)

$8.0 million

ACREAGE

As of June 30, 2018, Northern controlled leasehold of approximately 142,248 net acres targeting the Williston Basin Bakken and Three Forks formations. As of June 30, 2018, approximately 93% of the company’s North Dakota acreage position, and approximately 92% of its total acreage position, was developed, held by production or held by operations.

LIQUIDITY

At June 30, 2018, Northern had available liquidity of approximately $240.9 million, comprised of $200.9 million in cash on hand and $40.0 million of capacity on its first lien term loan facility.

HEDGING

Northern hedges portions of its expected production volumes to increase the predictability of its cash flow and to help maintain a strong financial position. The following tables summarize Northern’s open crude oil derivative and basis swap contracts scheduled to settle after June 30, 2018.

Crude Oil Derivative Swaps

Contract Period

Volume (Bbls)

Weighted Average Price (per Bbl)

2018:

3Q

1,477,460

$60.62

4Q

1,381,300

$60.44

2019:

1Q

1,240,200

$58.83

2Q

1,137,500

$58.03

3Q

863,600

$56.72

4Q

717,600

$55.70

2020:

1Q

682,500

$54.79

2Q

646,100

$55.29

3Q

349,600

$51.73

4Q

334,880

$51.23

2021:

1Q

322,200

$53.35

2Q

309,400

$58.09

Crude Oil Derivative Basis Swaps(1)

Contract Period

Total Volumes (Bbls)

Weighted Average Differential ($/Bbl)

2019

1,642,500

($1.78)

__________

(1)

Basis swaps are settled using the TMX UHC 1a index, as published by NGX.

SECOND QUARTER 2018 EARNINGS RELEASE CONFERENCE CALL

In conjunction with Northern’s release of its financial and operating results, investors, analysts and other interested parties are invited to listen to a conference call with management on Thursday, August 9, 2018 at 11:00 a.m. Central Time.

Those wishing to listen to the conference call may do so via the company’s website, www.northernoil.com, or by phone as follows:

Northern Oil and Gas, Inc. is an exploration and production company with a core area of focus in the Williston Basin Bakken and Three Forks play in North Dakota and Montana. More information about Northern Oil and Gas, Inc. can be found at www.NorthernOil.com.

SAFE HARBOR

This press release contains forward-looking statements regarding future events and future results that are subject to the safe harbors created under the Securities Act of 1933 (the “Securities Act”) and the Securities Exchange Act of 1934 (the “Exchange Act”). All statements other than statements of historical facts included in this release regarding Northern’s financial position, business strategy, plans and objectives of management for future operations, industry conditions, and indebtedness covenant compliance are forward-looking statements. When used in this release, forward-looking statements are generally accompanied by terms or phrases such as “estimate,” “project,” “predict,” “believe,” “expect,” “continue,” “anticipate,” “target,” “could,” “plan,” “intend,” “seek,” “goal,” “will,” “should,” “may” or other words and similar expressions that convey the uncertainty of future events or outcomes. Items contemplating or making assumptions about actual or potential future sales, market size, collaborations, and trends or operating results also constitute such forward-looking statements.

Forward-looking statements involve inherent risks and uncertainties, and important factors (many of which are beyond our company’s control) that could cause actual results to differ materially from those set forth in the forward-looking statements, including the following: changes in crude oil and natural gas prices, the pace of drilling and completions activity on Northern’s current properties and properties pending acquisition, Northern’s ability to acquire additional development opportunities, changes in Northern’s reserves estimates or the value thereof, general economic or industry conditions, nationally and/or in the communities in which Northern conducts business, changes in the interest rate environment, legislation or regulatory requirements, conditions of the securities markets, Northern’s ability to consummate any pending acquisition transactions, other risks and uncertainties related to the closing of pending acquisition transactions, Northern’s ability to raise or access capital, changes in accounting principles, policies or guidelines, financial or political instability, acts of war or terrorism, and other economic, competitive, governmental, regulatory and technical factors affecting our company’s operations, products and prices.

Northern has based these forward-looking statements on its current expectations and assumptions about future events. While management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties, most of which are difficult to predict and many of which are beyond Northern’s control. Northern does not undertake any duty to update or revise any forward-looking statements, except as may be required by the federal securities laws.

Adjusted Net Income and Adjusted EBITDA are non-GAAP measures. Northern defines Adjusted Net Income as net income (loss) excluding (i) (gain) loss on the mark-to-market of derivative instruments, net of tax, (ii) write-off of debt issuance costs, net of tax, and (iii) loss on the extinguishment of debt, net of tax. Northern defines Adjusted EBITDA as net income (loss) before (i) interest expense, (ii) income taxes, (iii) depreciation, depletion, amortization and accretion, (iv) (gain) loss on the mark-to-market of derivative instruments, (v) non-cash share based compensation expense, (vi) write-off of debt issuance costs, and (vii) loss on the extinguishment of debt. A reconciliation of each of these measures to the most directly comparable GAAP measure is included below. Management believes the use of these non-GAAP financial measures provides useful information to investors to gain an overall understanding of current financial performance. Specifically, management believes the non-GAAP results included herein provide useful information to both management and investors by excluding certain expenses and unrealized derivatives gains and losses that management believes are not indicative of Northern’s core operating results. In addition, these non-GAAP financial measures are used by management for budgeting and forecasting as well as subsequently measuring Northern’s performance, and management believes it is providing investors with financial measures that most closely align to its internal measurement processes.

Reconciliation of Adjusted Net Income

Three Months Ended June 30,

Six Months Ended June 30,

2018

2017

2018

2017

Net Income (Loss)

$

(96,546,698

)

$

13,801,859

$

(93,581,601

)

$

30,742,382

Add:

Impact of Selected Items:

(Gain) Loss on the Mark-to-Market of Derivative Instruments

29,935,931

(14,172,002

)

42,077,245

(31,228,544

)

Write-off of Debt Issuance Costs

—

95,135

—

95,135

Loss on the Extinguishment of Debt

90,832,975

—

90,832,975

—

Selected Items, Before Income Taxes

120,768,906

(14,076,867

)

132,910,220

(31,133,409

)

Income Tax of Selected Items(1)

(6,180,382

)

99,518

(9,912,004

)

159,429

Selected Items, Net of Income Taxes

114,588,524

(13,977,349

)

122,998,216

(30,973,980

)

Adjusted Net Income (Loss)

$

18,041,826

$

(175,490

)

$

29,416,615

$

(231,598

)

Weighted Average Shares Outstanding – Basic

196,140,610

61,643,862

131,039,552

61,545,555

Weighted Average Shares Outstanding – Diluted

196,413,013

61,885,952

131,248,726

61,928,799

Net Income (Loss) Per Common Share – Basic

$

(0.49

)

$

0.22

$

(0.71

)

$

0.50

Add:

Impact of Selected Items, Net of Income Taxes

0.58

(0.22

)

0.93

(0.50

)

Adjusted Net Income (Loss) Per Common Share – Basic

$

0.09

$

—

$

0.22

$

—

Net Income (Loss) Per Common Share – Diluted

$

(0.49

)

$

0.22

$

(0.71

)

$

0.50

Add:

Impact of Selected Items, Net of Income Taxes

0.58

(0.22

)

0.93

(0.50

)

Adjusted Net Income (Loss) Per Common Share – Diluted

$

0.09

$

—

$

0.22

$

—

__________

(1)

For the 2018 columns, this represents a tax impact using an estimated tax rate of 24.5% for the three and six months ended June 30, 2018, which includes a $23.4 million and $22.7 million adjustment for an increase in the valuation allowance for the three and six months ended June 30, 2018, respectively. For the 2017 columns, this represents a tax impact using an estimated tax rate of 37.1% and 37.8% for the three and six months ended June 30, 2017, respectively, which includes a $5.1 million and $11.6 million adjustment for a change in valuation allowance for the three and six months ended June 30, 2017, respectively.

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